Packer tool arrangement with rotating lug

ABSTRACT

A packer assembly requires only forces applied axially along an actuating means such as production tubing (either pushing down or pulling up) to actuate it between its operational states, such as a set state, a bypassed state, and a released state. The packer includes a tubular member that has a lug guide formed substantially within its inner surface. The packer further includes a mandrel that can be coupled to an actuating means and disposed within the tubular member, the mandrel further comprising a lug ring having at least one lug disposed in the lug guide. The tubular member is held in a substantially fixed position relative to the mandrel once the packer is initially set within a well-bore. The lug ring is free to rotate in response to forces applied to the tubing once the packer tool assembly is initially set.

BACKGROUND

When oil and gas wells are first drilled, sections of pipe arethreadably secured together and the segmented pipe is lowered into thewell-bore created by the drilling process. Cement is then typicallyintroduced between the well-bore and the outside surface of the pipe torigidly secure the pipe in place within the well-bore. This length ofcemented pipe is called a casing and provides a rigid support thatprevents the well-bore from collapsing in on itself Because the casingis expensive, it is desirable for the casing to be relatively permanent.Thus, it is important to protect the casing from the corrosiveproperties of the fluids that are typically produced from the well (e.g.oil, gas and other fluids from formations tapped by the well), as wellas fluids that may be pumped down into the well for purposes ofacidizing, formation fracturing, squeeze cementing, or other similaroperations known to those of skill in the art.

One common technique for protecting the casing as previously describedis through the use of a tool generally referred to as a packer. Packersare typically deployed within the annulus or bore of the casing andinclude sealing elements that, when forced against the annular surfaceof the casing, prevent the flow of fluids into the casing that are beingproduced just below it. The packer ensures that corrosive fluids areonly produced through the packer and a second pipe to which the packeris attached rather than through the casing itself

A packer is deployed by first lowering the packer into the casingattached to, for example, a length of production tubing or a wireline asis known to those of skill in the art. While being lowered into thewell, the packer is initially configured in a mode whereby it is able tomove freely within the bore of the casing until it reaches the zone of aformation from which the well is to produce. The packer is designed suchthat upon reaching the appropriate depth in an “armed” mode, it can betriggered or actuated through the application of forces from above toanchor itself against the annular surface of the casing while alsodisposing its sealing elements against the annular surface of thecasing. This process is known as “setting” the packer.

In the case of packers run into the hole already attached to tubingthrough which the well is to be produced, the setting of the packer istypically triggered by introducing fluid into the packer through thetubing. The bore of the packer is initially plugged on its down-hole endand as a result hydraulic forces develop inside of the packer and areused to trigger the setting process. Packers run into the hole bywireline are set by actuating a wireline device that uses gravity totrigger the setting process. Once set, the wireline and wireline deviceare removed and production tubing is then introduced and coupled to thepacker. In either case, once the packer is set, a pump out plug is blownout of the down-hole end of the packer to enable production from aperforated portion of the casing just below it. Regardless of the mannerin which the triggering or actuating force is generated and applied,most commercially available packers operate in a similar fashioninternally to achieve the desired “set” configuration.

Once production from a well (or at least from a particular zone withinthe well) has been completed, a packer is typically removed from thatlocation in the well-bore. Some packer designs permit the packer to bereleased from the set position through the application of forces to theproduction pipe or tubing to which the packer is attached. These forcesare typically axial (i.e. along the axis of the pipe or tubing), or somemay require rotational forces applied to the pipe or tubing that aretranslated into a torque at the packer. Other designs are permanentlyset and the only way they can be removed is by their destruction, suchas drilling them out of the casing. Some retrievable packers can bereleased through application of axial force, raised or lowered toanother zone, and then reset at the new depth without having to bepulled from the hole and re-armed. In the case of a reset, force appliedup-hole is used to reset the packer rather than hydraulic forces or awireline. Resetting these packers typically requires the ability toadminister a rotational force to the packer from above the ground inaddition to applying pulling and pushing (i.e. axial) forces.

The ever-increasing demand for oil and gas and the increasing price inresponse thereto, has motivated the drilling of wells to accessformations that are not easily reached with a primarily verticalwell-bore. Rather, access to many formations requires directional andeven horizontal drilling that may involve abrupt changes in direction(referred to as “doglegs”). As a result, the pipe used for the casingand especially for producing such wells has necessitated the use of moreflexible materials such as tubing that can be more easily run throughhorizontal and doglegged bores. The use of flexible tubing has made itvirtually impossible to use packer designs that require rotationalforces to manipulate the packer. This is because it is very difficult toachieve sufficient rotational force on a packer that is coupled at theend of what may be several thousand feet of flexible tubing. While apacker deployed under such conditions may initially be set usinghydraulic forces, current packer designs still require the applicationof rotational forces if the packer is to be easily released and reset atanother depth to avoid being removed from the well.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of embodiments of the invention, referencewill now be made to the accompanying drawings in which:

FIG. 1 is an illustration of a well-bore that becomes significantlyhorizontal to effectively access and produce from a formation.

FIGS. 2A-B form two parts of continuous drawing that illustrates across-sectional view of the top and bottom sections, respectively, of anembodiment of a hydraulically actuated packer incorporating aspects ofthe invention.

FIG. 2C illustrates a cross-sectional view of the top section of anembodiment of a wireline actuated packer incorporating various featuresof the invention.

FIGS. 3A-3B form two parts of a continuous drawing illustrating across-sectional view of the top and bottom sections of the hydraulicallyactuated packer of FIGS. 2A-B after being initially set.

FIG. 4 illustrates a cross-sectional view of the top section of thehydraulically actuated embodiment of FIGS. 3A-B wherein a bypass hasbeen enabled around packing elements of the packer and into the annulusof the casing in accordance with various aspects of the invention.

FIGS. 5A-5B show magnified quarter-sectional views of the top and bottomportions of the hydraulically actuated embodiment of FIGS. 2A, 2B, 3Aand 3B incorporating various features of the invention.

FIG. 5C illustrates an embodiment of the rotating lug assembly inaccordance with the invention.

FIG. 6 is a two-dimensional illustration of an embodiment of a groove orlug guide in accordance with the invention in which the rotating lugtravels to achieve actuation of the packer into various operationalstates, including “set,” “bypassed” and “released” states.

FIG. 7 is a two-dimensional illustration of an embodiment of a groovepattern in accordance with the invention in which the rotating lugtravels to achieve actuation of the packer into various operationalstates, including “set,” “released” and “bypass” modes, as well as anup-hole and down-hole position of the lug for purposes of relocating thepacker within the well-bore prior to resetting the packer.

NOTATION AND NOMENCLATURE

Certain terms are used throughout the following description and in theclaims to refer to particular features, apparatus, procedures, processesand actions resulting therefrom. Those skilled in the art may refer toan apparatus, procedure, process, result or a feature thereof bydifferent names. This document does not intend to distinguish betweencomponents, procedures or results that differ in name but not function.In the following discussion and in the claims, the terms “including” and“comprising” are used in an open-ended fashion, and thus should beinterpreted to mean “including, but not limited to . . . ”

DETAILED DESCRIPTION

The following discussion is directed to various embodiments of theinvention. Although one or more of these embodiments may be preferred,the embodiments disclosed should not be interpreted as, or otherwise beused for limiting the scope of the disclosure, including the claims,unless otherwise expressly specified herein. For example, an embodimentmay be hydraulically actuated (i.e. set) if run into the hole coupled totubing, yet various aspects of the invention can also be incorporatedinto embodiments using other known setting techniques, such as using awireline device. In addition, one skilled in the art will understandthat the following description has broad application, and the discussionof any particular embodiment is meant only to be exemplary of thatembodiment, and not intended to intimate that the scope of thedisclosure, including the claims, is limited to that embodiment. Forexample, while the various embodiments may employ one type of techniquefor initially setting the packer, packers employing other knowntechniques are considered within the scope of the present invention.

With reference to FIG. 1, a producing well is illustrated including adrilling rig 100, a directionally drilled well-bore 102 tappingformation 104. Disposed inside of well-bore 102 is a segmented casing110. Because of the directional bend required in the well-bore 102 toaccess formation 104, a length of flexible tubing 112 is typicallydisposed within the casing 110 through which the well produces fromformation 104. Perforations 108 are formed in the casing 102 throughwhich fluids are drawn into the casing 110. Packer 106 is typicallydisposed and “set” just above the perforations to prevent the fluidsfrom continuing up through the casing 110. The packer 106 instead forcesthe fluids drawn in through the perforations 108 to be directed into thebore of packer 106 and into the production tubing 112 to which thepacker 106 is coupled at its up-hole end.

As previously described, packers have been designed that can bereleased, re-positioned within the well bore, and then re-set withouthaving to be removed from the well-bore. One such packer design isdisclosed in U.S. Pat. No. 5,197,547 (hereinafter the '547 patent),which is incorporated herein in its entirety by this reference. Thepacker design disclosed in the '547 patent requires a rotational force,along with axially applied forces, to be applied at the up-hole end ofthe production medium to release the packer from the “set” mode andreset the packer while disposed within the well-bore. The application oftorque to actuate the packer in this manner becomes exceedinglydifficult when disposed in a directionally drilled well-bore such asthat illustrated in FIG. 1. When tubing is used as the productionmedium, the ability to translate torque applied at the up-hole end ofthe tubing to a sufficient rotational force at the packer is virtuallyimpossible, especially as the depth of the packer's deployment (and thusthe length of the tubing) increases.

Some packer designs employed under the drilling conditions described inFIG. 1 must be destructively drilled out of the well-bore to completethe well or at least a particular zone in a well (these are sometimesreferred to as permanent packers). At best, packer designs implementedunder the conditions generally described in FIG. 1 might have thecapability of being released through the application of axial forces onthe tubing. Once released, however, even they must be pulled from thewell bore and “re-armed” if they are to be redeployed. Packer designscapable of being reset without being removed and rearmed have heretoforerequired rotational forces that are difficult to create with tubing aswas previously discussed. One benefit of the packer assembly of thepresent invention provides the ability for a packer, especially onedeployed under conditions such as that illustrated in FIG. 1, to bereleased, repositioned and reset (i.e. actuated) through application ofonly axially applied (i.e. pulling and pushing) forces on the tubing T.

Moreover, aspects of the present invention also permits an additional“bypassed” state, between the “set” and “released” modes, where fluidsare permitted to bypass the seals into the casing for purposes ofperforming circulation while the packer remains in a “set” state. Thus,while in this bypass state, the packer remains anchored within thecasing and the sealing elements remain deployed until circulation iscomplete. During circulation, fluid is forced down through theproduction tubing causing fluids resting at the bottom of the well to belifted up from the bottom of the well. These fluids are then forced intointerstitial areas of the packer outside of the packer bore, around thesealing elements and ultimately into the annulus of the casing. Thisserves to avoid contact between the fluids being produced duringcirculation and the sealing elements, which would otherwise degrade thesealing elements and quickly render them ineffectual. Moreover, it is anadded benefit that the packer remains anchored within the casing duringcirculation.

FIGS. 2A and 2B illustrate the upper and lower portions respectively ofan embodiment of a packer assembly, disposed in a well casing C thatincorporates various features of the invention. The embodiment of FIGS.2A and 2B can be run into a well-bore (not shown) on tubing T and isactuated (i.e. triggered) hydraulically to become “set.” The tubing Tcan be threadedly coupled to an upper mandrel (or mandrel sub) 31 bythreads 20, thus rendering the bore 8 of tubing T in communication withthe packer bore 26 a. The packer bore 26 a is formed by upper mandrel 31and various other subcomponents that together form a packer mandrel aswill be described in detail below.

The mandrel sub 31 is telescopically received through the upper end of abody B, which is releasably connected to mandrel sub 31 by suitablefrangible means such as shear pins 32 as is well known to those of skillin the art. In an embodiment, shear pins 32 may extend through body Band into sub 31. An annular cap 33 is threadedly engaged in the upperend of body B at threads 134 and the cap 33 terminates in the shoulder34 internally of body B as shown. Mandrel sub 31 has shoulder 35extending outwardly between mandrel sub 31 and body B which engagesshoulder 34 when the packer is being unset so that mandrel sub 31 may bemoved up by the tubing T.

As shown in FIG. 2A, the body B forms a hollow spring cage housing 55 acontaining a resilient element 55. In an embodiment, the shear pins 32are shown extending through cap 33 and into mandrel sub 31, but those ofskill in the art will recognize that the location and type of suchfrangible means may be other than that in the example embodiment withoutexceeding the scope of the present invention. In an embodiment, thelongitudinal body B is hollow and resilient element 55 (which may be acoil spring or some other equivalent resilient element) is positionedtherein between the annular shoulder 56 at the lower end of body B andthe shoulder 35 a formed by the end of the mandrel sub 31 as shown.

The spring element 55 is typically collapsed when the tool is assembledas the body B is moved up on the packer mandrel to be secured to themandrel sub 31 by the frangible means 32. It remains collapsed orpartially collapsed as the body B is moved down along the packer mandrelby hydraulic forces created during the setting process as will bedescribed in more detail below. Those of skill in the art will recognizethat other known embodiments of packers may not make use of a resilientelement 55. For example, an alternate embodiment of a packer that doesnot make use of a resilient element 55 is disclosed in theabove-referenced '547 patent.

The packer mandrel may be formed of any suitable number of tubularportions, in addition to mandrel sub 31, as is known to those of skillin the art. In an embodiment, this may include an upper tubular portionor sub 14 (which is threadedly connected to mandrel sub 31 at 16) and alower tubular portion or sub 15, which are threadedly connected togetherthrough a rotatable lug assembly 500. A more detailed description of anembodiment of the rotatable lug assembly will be presented later in thedescription.

In an embodiment, a member referred to generally at 26 (and is sometimesreferred to as a packer support or a rubber mandrel), provides a supportfor the rubber sealing elements P that are used to seal the casing Cwhen the packer is set. The packer support 26 includes a support sleeve27 and upper 102 and lower 104 slip and cone assemblies. It serves toextend or move the packer or seal elements referred to generally at P,along with the upper and lower slip and cone anchor assemblies 102, 104,into sealing and securing relation with the inner surface or annularwall of the casing C.

In an embodiment, the upper assembly 102 includes upper slips 57supported at the lower end of the body B in a manner well known to thoseskilled in the art and are adjacent to (and while in the “armed” state,preferably not in contact with) an annular, tapered surface 58 a forminga conical surface or cone supported on the upper end of the packersupport 26. The lower assembly 104 includes a movable end portion 60 onthe lower end of packer support 26, which has an annular tapered surface61 forming a conical surface or cones for engagement with adjacent lowerslips 62 on member 25 when the packer is set. Those of skill in the artwill recognize that the structure and relationship of the cones 58 a, 61and slips 57, 62 may be accomplished in any manner suitable for settingthe packer.

In an embodiment, the upper end of packer support 26 is secured bysuitable means such as threads 56 c to support sleeve 27 as shown inFIG. 2A. The packers or seal elements P are supported thereon formovement as is well-known in the art. The lower end portion 29 of packersupport 26 is movable relative to support sleeve 27 and packer support26 to expand or extend the packers P into sealing engagement with theannular surface of the casing C. An annular shoulder 67 on supportsleeve 27 engages inwardly extending shoulder 68 on the movable endportion 60 and supports the movable end portion on packer support 26while accommodating movement of such end portion 60 when the packer isset. Triggering the packer to set causes forces to compress the packersP and extends them and the slip and cone arrangements 102, 104 intosealing and securing relation within the annular opening.

In an embodiment, the support sleeve 27 extends longitudinally of thepacker mandrel as shown in the drawings and terminates in end cap 69,which may be threadedly engaged thereon and assists in supporting thepartially surrounding member 25 on the sleeve 27. The member 25 may beformed of any desired number of tubular subs or portions, and mayinclude an upper tubular sub 72 and a lower tubular sub 25 a, which maybe threadedly coupled as shown at 25 b or coupled in any appropriatemanner as the packer is assembled. The member 25 includes a groove 606formed within its internal surface into which rotating lugs 514 a and514 b (FIG. 5C) are disposed in a preset or armed position as will bedescribed in greater detail below.

In an embodiment, drag blocks referred to generally at 70 and springs 71are supported in the tubular sub 72. Member 25 may be formed by theupper tubular sub or member 72 and the lower tubular sub or member 25 a,which are connected together to form the member 25 as previouslydiscussed. When the drag blocks 70 are engaged during the initialsetting of the packer, they are urged outwardly by spring means 71 forengagement with the casing C to enable the packer mandrel to bevertically manipulated relative to the member 25. Verticallymanipulating the mandrel causes lugs 514 a, 514 b to be advanced withingroove 606 to achieve various operational states of the packer,including the “bypassed” and “released” states, and then back to the“set” state if desired. A more detailed description of the rotatable lugassembly 500, FIG. 5C and the operational states will be presentedbelow.

In an embodiment, the springs 71 will be initially collapsed and securedto the support sleeve 27 and member 25 prior to deployment and while inthe “armed” state prior to triggering the setting of the packer. Shearpins 72 a may be employed to maintain the drag blocks in thisinoperative or non-engaged state. Shear pins 72 a may also be used tosecure the member 25 so that slips 62 are supported in a non-engagingposition adjacent the tapered surface (i.e. cone) 61 while the packer isdeployed within the well bore casing C. Those of skill in the art willrecognize that other equivalent means may be employed to provide thenecessary anchoring of the tubular member 25 to render it stationarywith respect to the packer mandrel without consequence to thepatentability of the invention as disclosed.

In an embodiment, rotatable lug assembly 500, FIG. 5C couples upper 14and lower 15 mandrel subs together with a rotatable lug ring 510 therebetween. The packer mandrel, along with the rotatable lug assembly 500,is disposed within tubular member sub 25 a. A groove or lug guide 606,FIGS. 6 and 7 is formed within the inside surface of the tubular membersub 25 a. The groove provides a guide channel in which lugs 514 a, btravel between mandrel resting points (e.g. 602, 604, 608, 612), eachrepresenting a particular functional state of the packer while themandrel is in that position. Because the rotatable lug ring 510 is freeto rotate, placing downward force on the mandrel will cause the lug totravel through the groove to the extent that the components within thepacker can compress (illustrated by dotted lines at 603, 605, and 607).Once in one of the bottom positions, pulling up on the mandrel causesthe lugs 512 to rotate into one of the functional positions and remainthere until another downward force is applied.

In an embodiment, the groove or guide patterns 606 of FIG. 6 or 7 can berepeated over 180 degrees of the tubular sub 25 a and thus, each lug 514a, b makes one trip through the same pattern over 180 degrees ofrotation. Those of skill in the art will recognize that variations ofthe embodiment of rotatable lug assembly 500 may be made withoutexceeding the intended scope of the invention. For example, the patterncould also be formed over 360 degrees such that the rotatable lug ring510 will rotate one complete turn through the entire guide beforerepeating. The ring 510 could also be implemented with only one lugrather than two.

In an embodiment of the guide 606, FIG. 6, the pattern can have a firstlocation 602 wherein when the lugs 514 (and thus the mandrel) are atrest, and the packer operates in the “set” state. Actuating the mandrelwith a down-hole axial force on the tubing T and then with a pulling orup-hole axial force will cause the lugs 514 to rotate into and come torest in position 604, wherein the packer is in the “bypassed” state.Again, actuating the mandrel as described above causes the lugs 514 torotate into the position 608, wherein the packer is in the “released”state. From their, the packer can be pulled up-hole, either out of thewell completely or to another higher zone location. In the lattersituation, the packer can be actuated as described before, advancing thelugs into the set state once again at 602. In an embodiment as shown inFIG. 7, an additional position at 612 is added permitting the packer tobe lowered down-hole after release. Downward force and then a pullupward as previously described places the packer back into position 602and into the “set” state once again.

In an embodiment, a pump out plug referred to generally at 36 is shownadjacent the lower end 29 of the mandrel sub 15. The pump out plug mayinclude a tubular housing 37 threadedly connected to the mandrel sub 15,and a plug portion 38 releasably secured in the housing by any suitablemeans such as a frangible member, or shear pins 39. After the packer isset, sufficient hydraulic pressure can be applied to the bore of themandrel to shear the pin(s) 39 and release the plug 38 to enable fluidflow through the mandrel bore 26 a and the packer as desired.

In assembling a packer for deployment that includes features of thepresent invention, virtually all of the components except for therotating lug assembly 500 and lower tubular sub 25 a, may be assembledusing any number of well-known designs in any well-known manner to placesuch a design in a “preset” or “armed” state. With reference to theexample embodiment of FIGS. 2A and 2B, mandrel sub 31 and cap 33 areassembled in a well known manner on body B, with a resilient element 55disposed therein. Body B is then releasably secured to the mandrel ofthe packer at mandrel sub 31 by any suitable frangible means well knownin the art such as shear pins 32. As previously discussed, those ofskill in the art will recognize that body B may be employed without thespring element 55. This does not affect the manner in which features ofthe present invention are incorporated into the embodiment.

In an embodiment, shear pins 72 a are introduced as shown in FIG. 2B toextend through member 25 a and into support sleeve 27 to secure supportsleeve 27 in position as the packer is lowered into the well bore. Themandrel (i.e. subs 14, 15 coupled through its rotatable lug assembly500) is initially inserted through the entry point 610 of groove 606.The lugs 514 are located at initial position 601, which will beindicated by the fact that the lugs 514 can be viewed and accessedthrough an opening that extends completely through the tubular sub 26 a.Shear pins can be inserted through this opening and the lugs 514 to holdthe rotatable lug assembly 500 into this position. Once assembled andinitially set, those of skill in the art will recognize that the mandrelwill not be able to exit the guide 606, but will be stopped at the pointat which the components of the packer have reached maximum compression,for example, at lug location 605.

In an embodiment, the packer is threadedly secured with the tubing T asshown and is lowered into a well-bore casing C. Once the packer has beenlowered to the desired position within casing C, the packer ishydraulically triggered to become “set” in a manner well known in theart. Fluid is pumped down through the tubing T and into the bore 26 a ofthe packer. Internal pressure begins building within the packer,including inside the spring housing 55 a of body B as the fluid flowsinto the housing 55 a through channels 5, FIG. 2A. The pressure insidethe spring housing 55 begins forcing body B downward toward the topslips 57 of the upper slips and cones arrangement 102 and forces areapplied upward against sub 31. When the resulting shearing force onshear pins 32 exceeds some predetermined value, the shearing pins giveway and body B is able to press downward on the slips 57, as well as therubber mandrel 26 generally.

Body B continues to press downwardly and the top slips 57 are presseddownward and make initial contact with top cones (not shown) of theupper slip and cone arrangement 102. Continued movement of the packersupport or rubber mandrel 26 (including support sleeve 27) shears pins72 a to release the member 25 and the drag block springs 71 of dragblock assembly 70. These forces are also translated to the rubbermandrel 26, causing the top cones (not shown) of lower slip and conearrangements 104 to initially contact the bottom slips 62. This resultsbecause second end portion 60 of the packer support 26 contacts lowerslips 62 to force the lower slips 62 and tapered surface 61 out intosecuring engagement with the surface defining the opening in which thepresent invention is positioned. This stops the downward movement ofmovable portion 60 of the packer support 26.

Continued downward hydraulic force on body B and packer support 26forces packer support 26, packer P and support sleeve 27 downward.Packer P is thus forced against packer support second end portion 60which forces or extends the packer or seal elements P out into sealingengagement with the annular surface of the casing C. The above actioncontinues until the packer P and the upper slip 57 of upper slip andcone assembly 102 is firmly engaged with the annular surface of thecasing C. Finally, the hydraulic forces cause the shear pins 512 in therotatable lug assembly to sheer, which frees the packer mandrel (e.g.subs 31, 14 and 15) to move freely with respect to tubular member 25,including subs 25 a and 72. This causes the packer mandrel to movedownwardly and causes rotatable lug 510, (FIG. 5C) to rotate such thatlugs 514 a, b come to rest at the “set” position (602, FIGS. 6 and 7).The foregoing mechanical sequence that occurs during the setting processas triggered from the “armed” condition of the packer actually causes arelatively short longitudinal movement of the components supported onthe rubber mandrel 26.

Once set, pump-out plug 38 can be blown out by shearing pins 39. Withplug 38 removed, the well may begin producing through the lower end 29of the packer. Those of skill in the art will recognize that the packeris designed to “avalanche” into the “set” state by sequencing thefailure of the various shear pins in the manner described above. Thiscan be accomplished by designing the shear pins to fail at increasingthresholds of force to effectuate the sequential nature of the settingprocess.

An illustration of the embodiment of FIGS. 2A and 2B with its variouscomponents in the “set” state is shown in FIGS. 3A and 3B. Those ofskill in the art will recognize that variations in packer designs toaccomplish this sequential process may be varied in numerous ways toachieve the same result. For example, the thickness or number of shearpins can affect the threshold force at which they shear. It is alsopossible to locate the shear pins or other components in differentlocations. Those of skill in the art will recognize that the manner inwhich the packer is designed to achieve the “set” state is not pertinentto the scope of the instant invention.

In addition, while the embodiment illustrated in FIGS. 2A, 2B, 3A, 3B,5A and 5B is one triggered to set hydraulically, those of skill in theart will recognize that embodiments actuated using other techniques tocreate the actuating forces are well-known and may be used withoutimpact upon the manner in which features of the present invention areemployed therein. For example, the embodiment could be adapted to be setthrough wireline techniques known to those of skill in the art. FIG. 2Cillustrates the use of a wireline device W by which to establish thedownward force on body B to initiate or trigger the set process. Onedifference in the two embodiments is that the wireline embodiment doesnot require the channels 5, FIG. 2A that provide fluid communicationbetween the packer bore 26 a and the spring housing 55 a. The componentscomprising and manner of operation of wireline actuating devices arewell-known to those of skill in the art and thus will not be detailedhere.

Once production from a current zone has been completed, or circulationis desired, an operator at the surface can apply a force axially alongthe tubing that causes the lugs 514 to move away from the “set” restpoint 602 in guide 606 and to contact declined surface 609 of guide 606.The axially applied pushing force will cause the rotatable lug ring 510to rotate, causing the lugs 514 to travel down the guide 606 and toreach vertical segment 630. There, the internal components of the packercan become substantially compressed and begin resisting any furthertravel of the packer mandrel in the down-hole direction such as atposition 607. This is because the packer is still set and all of theanchoring and sealing components are maximally disposed against theinside surface of the casing C. A pulling force applied to the tubing Tthen causes the packer mandrel to pull up and causes the lugs 514 totravel to the top of vertical groove segment 630 until it contactsinclined surface 632. At this point, the lug ring 510 rotates and causesthe lugs 514 to travel into position 604. This position places thepacker into the “bypassed” state as will be described in more detailbelow. In the bypassed state, the mandrel has been pulled up, but not tothe level at which the anchoring and sealing components will bereleased. The packer can therefore be bypassed during, for example,circulation can be advantageously conducted while the packer is still ina sealed and anchored state.

Once circulation is complete, the packer can be actuated again, aspreviously described, first with a force directed axially along thetubing T and down-hole in direction. This will bring the lugs 514 intothe vertical segment 636 of guide 606. Pulling up-hole on the tubing Twill cause the lugs 514 to move up and into the highest state positionin the guide 606 at position 608. At this point, the body B will becompletely extended toward the upper mandrel 31 and the spring element55 will be substantially uncompressed. The force will be just sufficientto begin lifting the upper slips 57 from the top cones (not shown) andthe internal upper and lower anchoring components, as well as thesealing elements will begin to release from their position against theinner wall of the casing C. The mechanisms by which the slips andsealing elements can be made to release are well-known to those of skillin the art. Once released, the packer can be lifted by the tubing Teither completely from the hole, or to a new location that is higherthan the previous location in the well-bore.

In the embodiment of guide 606 disclosed in FIG. 6, the packer caneither be lifted as described above, or it can actually be re-set bypushing down on the tubing T, causing the lug to travel down thevertical guide segment 638 to the point where the upper mandrel beginsto compress the spring mechanism 55, causing the process by which theupper slips 57 begin to re-engage with the upper cone of cones 58. Thismovement continues, aided by the drag blocks 70 which are still engagedand provide just enough resistance to get the setting sequence startedagain as was previously described above for the initial setting of thepacker. The only difference is that the drag blocks 70 are alreadyengaged. As the upper 58 and lower 62 slips are pressed back out, theyengage the casing C while the sealing elements P are again forced out toengage the casing C again as well. Eventually, the lugs 514 no longermove substantially downward in vertical groove segment 638, reaching thepoint (e.g. at 605) wherein little if any more compression is possible.A force applied in the up-hole direction pulls the packer mandrel andthus the lugs 514 back up against inclined guide surface 640, causingthe lugs 514 to achieve the resting position 602 at which the packer isreturned to the “set” state.

In the embodiment of guide 606 as illustrated in FIG. 7, an additionalrest position 612 is added after 608 in the sequence. This additionalresting position provided after the packer is released at 608 is toprovide the ability to lower the packer deeper into the well prior toresetting it as described above. Once again, a force directed up-holewill cause the lugs 514 to move into the intermediate position 650, fromwhere the packer can be moved up-hole if desired. A force directeddown-hole while in 650 will cause the lugs 514 to enter vertical segment638 from where the packer can be reset as was described above.

When the packer is placed into the “bypassed” mode (i.e. the lugs 514are actuated into position 604), the position of the rubber mandrel 26is raised just enough to leave the packer in the set mode, but enough tocause bypass channels 410 to be raised and to come into communicationwith upper bypass channels 412. The proximate relationship of the bypasschannels 410, 412 is illustrated in FIG. 4. During circulation, fluidproduced through the circulation process is permitted to enter thebypass channels 410, which permit the fluid to flow past the stilldeployed sealing elements P. The fluid is then permitted to enter theoverlapping upper bypass channels 412, and ultimately into the casing Cthrough the upper slip and cone assemblies 102. One of the advantages ofthis “bypassed” state is that the packer remains securely anchored as inthe “set” state, which ensures that the packer is not as likely to beblown out of the well during circulation. Moreover, the sealing elementsP do not some in contact with the fluid produced and thus are as likelyto corrode.

Various embodiments of the rotating lug assembly (500, FIG. 5C) andvarious embodiments of the groove or lug guide (606, FIGS. 6, 7) can beincorporated into existing packer designs known to those of skill in theart. The rotatable lug assembly is shear pinned to a start position thatensures that the packers are able to become “set” as they werepreviously designed, with the packer mandrel becoming free to beactuated after the packer has achieved its initial “set” state. Therotatable lug assembly and lug guide permit the lugs to move through theguide by applying only forces along the axis of the tubing because thelug is able to freely rotate as the lugs are forced to move through theguide by the actuating forces as previously described. As a result,packers can be triggered into their “set” state in accordance with theirwell-known design, and then may be sequenced into other desirablestates. This is accomplished through simple application of sufficientdown-hole force axially along the tubing to take the packer out of theresting position in its current state, and then applying sufficientup-hole force axially along the tubing to cause the lugs to move throughtheir guide as they rotate on their rotatable lug ring.

Thus, a packer may be bypassed while still being set, may be releasedfrom its set position for repositioning movement or complete removalfrom the well-bore, and may be reset at a different position within thewell-bore without the need to remove the packer and to rearm the packerfor redeployment. Further, movement between these states of operationdoes not require any rotational forces to be applied and translated downthe tubing, which is extremely difficult to accomplish reliably.

The foregoing is by way of example only, and changes can be made withoutdeparting from the scope of the invention which is more properlyencompassed by the following claims.

1. A packer apparatus comprising: a tubular member comprising a lugguide formed substantially within its inner surface; a mandrel operativeto be coupled to an actuating means and disposed within the tubularmember, the mandrel further comprising a lug ring having at least onelug disposed in the lug guide; means for maintaining the tubular memberin a substantially fixed position relative to the mandrel once saidpacker is initially set within a well-bore; and wherein the lug ring isoperative to rotate in response to forces applied to the actuating meansonce the packer tool assembly is initially set.
 2. The packer apparatusof claim 1 wherein the lug guide comprises a plurality of state andintermediate positions sequentially connected through a plurality ofguide segments, each of the state positions corresponding to anoperational state of said packer, said packer operative in the one ofthe operational states corresponding to the state position currentlyoccupied by the at least one lug.
 3. The packer apparatus of claim 3wherein the at least one lug is operative to be actuated from one stateposition to a next state position of the lug guide by first applying adownward axial force on the mandrel through the actuating means to urgethe at least one lug into a next intermediate position of the lug guide,and then applying an upward axial force on the mandrel through theactuating means to urge the at least one lug into a next state positionof the lug guide.
 4. The packer apparatus of claim 3 wherein one or moreof the state positions of the lug guide are each interconnected with anintermediate position through a declining guide segment, and one or moreof the intermediate positions are each coupled to a state positionthrough an inclining guide segment.
 5. The packer apparatus of claim 4wherein: a first of the state positions of the lug guide corresponds toa set state wherein said packer is sealably anchored within thewell-bore; and a second of the state positions of the lug guidecorresponds to a released state wherein said packer can be repositionedwithin the well-bore.
 6. The packer apparatus of claim 5 wherein a thirdof the state positions of the lug guide corresponds to a bypassed statewherein said packer operates in a bypassed mode.
 7. The packer apparatusof claim 6 wherein said packer remains sealably anchored within thewell-bore while operating in the bypassed state.
 8. The packer apparatusof claim 7 wherein the lug guide is circular and the plurality of statepositions begins with the set state, then the bypassed state, then thereleased state, with intermediate states there between, and the releasedstate connected with the set state.
 9. The packer apparatus of claim 6wherein said packer is initially disposed in the well-bore in an armedstate, wherein the at least one lug is releasably restrained within aguide segment connecting the set state position to a previousintermediate position by frangible means to prevent the at least one lugfrom being urged into the set state until a triggering force applied toset said packer exceeds a predetermined threshold.
 10. The packerapparatus of claim 8 wherein the triggering force is appliedhydraulically.
 11. The packer apparatus of claim 7 wherein thetriggering force is applied by wireline.
 12. The packer apparatus ofclaim 3 wherein the released state comprises a first released stateposition in the lug guide wherein said packer can be repositioned in anup-hole direction from its previous position in the well-bore; and asecond released state position wherein said packer can be repositionedin a down-hole direction from its previous position in the well-bore.13. The packer apparatus of claim 1 wherein the actuating means is alength of production tubing.
 14. A method of actuating a packer, saidpacker comprising a mandrel, the mandrel comprising a rotatable lugring, the lug ring comprising at least one lug, the mandrel beingdisposed within a tubular member, the at least one lug being disposedwithin a lug guide formed substantially within the inner surface of thetubular member and having a plurality of state positions and a pluralityof intermediate positions there between, each of the state andintermediate positions sequentially interconnected through a guidesegment, said method comprising: setting the packer within a well bore,said setting further comprising maintaining the tubular member in afixed position relative to the mandrel; applying a downward axial forceon the mandrel to urge the at least one lug through a declining one ofthe guide segments into a next intermediate position of the lug; andapplying an upward axial force on the mandrel to urge the at least onelug through an inclining one of the guide segments into a next stateposition of the lug guide.
 15. The method of claim 14 wherein: a firstof the state positions of the lug guide corresponds to a set statewherein the packer is sealably anchored within the well-bore; and asecond of the state positions of the lug guide corresponds to a releasedstate wherein the packer can be repositioned within the well-bore. 16.The method of claim 15 wherein a third of the state positions of the lugguide corresponds to a bypassed state wherein the packer operates in abypassed mode while remaining sealably anchored within the well-bore.17. The method of claim 16 wherein said identifying further comprisesarming the packer for deployment within the well-bore, said armingfurther comprising releasably securing the at least one lug within adeclining one of the lug guides connecting a previous intermediateposition with the set state position, preventing the at least one lugfrom being urged into the set state position in response to a triggeringforce that has not exceeded a predetermined threshold.
 18. The method ofclaim 17 further comprising: deploying the armed packer within awell-bore; and wherein said setting further comprises providing atriggering force to the packer that exceeds the predetermined threshold.19. The method of claim 14 wherein the applied upward and downwardforces applied to the mandrel are applied through a length of productiontubing coupled to the mandrel.
 20. The method of claim 18 wherein saidproviding further comprises pumping fluid into the packer through alength of production tubing coupled to the mandrel.